Corrosion is now recognized as a serious problem in the development of geoenergy sources, including oil and natural gas reserves, geothermal, and geopressured systems. The corrosion problems are greatly aggravated by the presence of acid gases such as hydrogen sulfide and carbon dioxide, and by the co-production of brine solutions. Although the exact cost of corrosion to the oil and gas industry is difficult to establish, it is estimated to be in excess of ten percent of the annual investment of the industry. Accordingly, corrosion is an enormous cost to the industry every year.
The exploration and production corrosion problems becomes more severe as production from deeper formation becomes increasingly attractive. For example, the production of deep, sour gas reserves along the Rocky Mountains, and the deep geopressured zones in the Southern United States encounter bottom hole temperatures as high as 200.degree. C. with pressure ranging up to 20,000 psi. More importantly is the fact that the produced gas may contain as little as 20% hydrocarbon (principally methane) with the balance being the acid gas carbon dioxide and hydrogen sulfide. These gases generally exist along with a high salinity sodium chloride brine in the producing formations with chloride contents ranging as high as several mols per kilogram of water. The pH of the downhole fluids may be as low as 2-3. Because the corrosivity of a fluid is frequently reflected by its pH value (the lower the pH, the more corrosive the fluid), it is clear that deep sour gas fluids are very corrosive systems indeed.
In the case of geopressured and geothermal systems, the acid gas contents are normally much lower. However, these systems are sometimes characterized by very high salinity brines and very high bottom hole temperatures. For example, the Salton Sea brines in Southern California contain as much as 150,000 ppm of chloride with bottom hole temperatures as high as 310.degree. C. These fluids have ph values of 4-5, which are considerably higher than those estimated for deep sour gas systems. However, the higher bottom hole temperatures may more than compensate for the higher pH as far as corrosion severity is concerned.
As an alternative to the use of high alloy components (high cost as compared to common carbon steels), corrosion inhibitors have drawn considerable interest for mitigating corrosion downhole in producing wells. Inhibitors are intuitively attractive, since they permit the use of regular carbon steel components rather than the much more expensive high nickel, cobalt and chromium alloys. However, few inhibitors have been demonstrated to be effective under the extreme conditions (particularly of temperature) now encountered in many geoenergy formations. Certainly, the traditional amine based inhibitor formulations are unlikely to be effective because the mechanism of inhibition involves physical adsorption of the amine onto the metal surface to form a hydrophobic barrier film.
An attractive alternative is to use an inhibitor that chemically reacts with a surface to form an impervious film which will protect the underlying metal from further corrosion. The so called "passivating" inhibitors (e.g., chromate) belong to this class, and are frequently effective under very extreme conditions. The present invention, though different, and a continuing and dynamic process, performs as a corrosion inhibitor of this general nature.
This invention is also applicable to the corrosion protection of drill pipe through which drilling fluids containing the above mentioned corrodents are passed. In this present invention, the currently used drilling muds continue to perform as intended without tendency to coalesce and thus be reduced or eliminated in effectiveness.
In accordance with 37 C.F.R. .sctn.1.56 and 1.97, the following references are disclosed:
Kauffman and Gay, "An Effective Passivating Oil Field Corrosion Control System", Final Technical Report, Mar. 31, 1986.
The original work made for this invention was reviewed by a confidential review of the U.S. Department of Energy under Contract No. 03RI 008601, later examined through proprietary and confidential testing and validation performed by the Bureau of Engineering Research of the University of New Mexico College of Engineering under Contract DFGOI85CE15200. To Applicant's knowledge, the only report or document prepared as a result of this work which may be a publication is the above-cited reference. This Report is available upon request from the U.S. Department of Energy Technical Information Center.
This reference generally discusses the type of research performed and future research proposed by the inventor of the present invention in order to demonstrate the process claimed in the application. The information provided in the Final Technical Report is general in nature and does not disclose the invention of the present application. Ternisien, J. A., et al., "Corrosion of Semi-Stainless Steel by Natural Gas from the Lacq Field", 249 Comptus Rendus (French) 1655-1657 (1959).
This reference reports corrosion products consisting of an outer friable layer and an inner compact layer the latter composed of pyrite pyrrholite, and offering protection from the gas.
U.S. Pat. No. 3,989,459, Nose, Y., et al., "Method of Preventing Corrosion of Steelworks", Nov. 2, 1976.
A method for preventing corrosion of steelworks by a flowing corrosive solution having a pH of 6.7 to 7.1, and comprising water, ammonia, and hydrogen sulfide. Particularly, a method to prevent corrosion of steel material by adding 5 ppm to 0.3 wt % as the amount of available sulfur of sulfur, ammonium polysulfide and/or alkali polysulfides to the fluid as available.
None of the above-discussed references are sufficiently material, alone or in combination to render unpatentable the claims of the present application.